The present invention relates to nuclear magnetic resonance (NMR) logging and is directed more specifically to a system and method for detecting the presence and estimating the quantity of gaseous and liquid hydrocarbons in the near wellbore zone.
Petrophysical parameters of a geologic formation which are typically used to determine whether the formation will produce viable amounts of hydrocarbons include the formation porosity PHI, fluid saturation S, the volume of the formation, and its permeability K. Formation porosity is the Dore volume per unit volume of formation; it is the fraction of the total volume of a sample that is occupied by pores or voids. The saturation S of a formation is the fraction of a its pore volume occupied by the fluid of interest. Thus, water saturation S.sub.W is the fraction of the pore volume which contains water. The water saturation of a formation can vary from 100% to a small value which cannot be displaced by oil, and is referred to as irreducible water saturation S.sub.Wirr. For practical purposes it can be assumed that the oil or hydrocarbon saturation of the formation S.sub.O is equal to S.sub.O =1-S.sub.W. Obviously, if the formation's pore space is completely filled with water, that is if S.sub.W =1, such a formation is of no interest for the purposes of an oil search. On the other hand, if the formation is at S.sub.Wirr it will produce all hydrocarbons and no water. Finally, the permeability K of a formation is a measure of the ease with which fluids can flow through the formation, i.e., its producibility.
Nuclear magnetic resonance (NMR) logging is among the most important methods which have been developed to determine these and other parameters of interest for a geologic formation and clearly has the potential to become the measurement of choice for determining formation porosity. At least in part this is due to the fact that unlike nuclear porosity logs, the NMR measurement is environmentally safe and is unaffected by variations in matrix mineralogy. The NMR logging method is based on the observation that when an assembly of magnetic moments, such as those of hydrogen nuclei, are exposed to a static magnetic field they tend to align along the direction of the magnetic field, resulting in bulk magnetization. The rate at which equilibrium is established in such bulk magnetization upon provision of a static magnetic field is characterized by the parameter T.sub.1, known as the spin-lattice relaxation time. Another related and frequently used NMR logging parameter is the so called spin-spin relaxation time constant T.sub.2 (also known as transverse relaxation time) which is an expression of the relaxation due to non-homogeneities in the local magnetic field over the sensing volume of the logging tool.
Another measurement parameter used in NMR well logging is the formation diffusion D. Generally, diffusion refers to the motion of atoms in a gaseous or liquid state due to their thermal energy. The diffusion parameter D is dependent on the pore sizes of the formation and offers much promise as a separate permeability indicator. In an uniform magnetic field, diffusion has little effect on the decay rate of the measured NMR echoes. In a gradient magnetic field, however, diffusion causes atoms to move from their original positions to new ones, which moves also cause these atoms to acquire a different phase shifts compared to atoms that did not move, and will thus contribute to a faster rate of relaxation. Therefore, in a gradient magnetic field diffusion is a logging parameter which can provide independent information about the structure of the geologic formation of interest, the properties of the fluids in it, and their interaction.
It has been observed that the mechanisms which determine the values of T.sub.1, T.sub.2 and D depend on the molecular dynamics of the sample being tested In bulk volume liquids, typically found in large pores of the formation, molecular dynamics is a function of molecular size and inter-molecular interactions which are different for each fluid. Thus, water, gas and different types of oil each have different T.sub.1, T.sub.2 and D values. On the other hand, molecular dynamics in a heterogeneous media, such as a porous solid which contains liquid in its pores, differs significantly from the dynamics of the bulk liquid and generally depends on the mechanism of interaction between the liquid and the pores of the solid media. It will thus be appreciated that a correct interpretation of the measurement parameters T.sub.1, T.sub.2 and D can provide valuable information relating to the types of fluids involved, the structure of the formation and other well logging parameters of interest.
A major barrier to using NMR logging alone for determination of porosity and other parameters of interest in the past has been the widespread belief that a near-wellbore NMR measurement cannot detect hydrocarbon gases. Failure to recognize such gases may result in their contribution being misinterpreted as bound fluid, which mistake may in turn result in excessively high irreducible water saturations and correspondingly incorrect permeability estimates. It has recently been found, however, that the NMR properties of gas are in fact quite different from those of water and oil under typical reservoir conditions and thus can be used to quantify the gas phase in a reservoir. More specifically, the Magnetic Resonance Imaging Log (MRIL.RTM.) tools of NUMAR Corporation have registered the gas effect as distortion in the bound volume irreducible (BVI) and/or free fluid index (FFI) measurements.
In a recent paper, entitles "NMR Logging of Natural Gas Reservoirs," paper N, presented at the 36th Annual SPWLA Symposium, Paris, Jun. 26-29, 1995, Akkurt, R. et al. have shown one approach of using the capabilities provided by NUMAR's MRIL.RTM. tool for detection of gas. The content of the Akkurt et al paper is incorporated herein for all purposes. In this paper, the authors point out that NMR signals from gas protons are detectable, and derive T.sub.1 relaxation and diffusion properties of methane-dominated natural gas mixtures at typical reservoir conditions. The magnetic field gradient of the MRIL.RTM. is used to separate and to quantify water, oil and gas saturations based solely on NMR data.
The results in the Akkurt paper are based on the NUMAR MRIL-C tool, the output of which is used to obtain T.sub.2 spectra. T.sub.2 spectra are extracted from the raw CPMG echo trains by breaking the total NMR signal M(t) into N components, called bins, according to the formula: ##EQU1## where a.sub.i is the porosity associated with the i-th bin. Each bin is characterized by a fixed center transverse relaxation time T.sub.2i. The total NMR porosity is then determined as the sum of the porosities a.sub.i in all bins. The T.sub.2 spectrum model is discussed in detail; for example, in Prammer, M. G., "NMR Pore Size Distributions and Permeability at the Well Site," paper SPE 28368, presented at the 69-th Annual Technical Conference and Exhibition, Society of Petroleum Engineers, New Orleans, Sep. 25-28, 1994, the content of which is expressly incorporated herein for all purposes.
On the basis of the T.sub.2 spectra, two specific methods for gas measurements are proposed in the Akkurt paper and will be considered briefly next to provide relevant background information. The first method is entitled "differential spectrum method" (DSM). The DSM is based on the observation that often light oil and natural gas exhibit distinctly separated T.sub.2 measurements in the presence of a magnetic field gradient, even though they may have overlapping T.sub.1 measurement values. Also, it has been observed that brine and water have distinctly different T.sub.1 measurements, even though their D.sub.0 values may overlap. The DSM makes use of these observations and is illustrated in FIG. 1 in a specific example for a sandstone reservoir containing brine, light oil and gas. According to the Akkurt et al. paper, two separate logging passes are made with different wait times TR.sub.l and TR.sub.s, such that the longer time TR.sub.l .gtoreq.T.sub.1g, and the shorter time satisfies the relationship T.sub.1g .gtoreq.TR.sub.s .gtoreq.3T.sub.1wmax.
Due to the large T.sub.1 contrast between the brine and the hydrocarbons, the water signal disappears when the spectra of the two signals are subtracted, as shown in FIG. 1. Thus, the differential T.sub.2 spectrum contains only hydrocarbon signals. It should be noted that the subtraction of the T.sub.2 spectra also eliminates all bound water, making the DSM very useful in shaly sands.
The second method proposed in the Akkurt et al. paper is called "shifted spectrum method" (SSM). Conceptually the method is based on the observation that since the surface relaxation for gas is negligible, the apparent T.sub.2 relaxation can be expressed as: ##EQU2## where G is the magnetic field gradient, D is the diffusion coefficient, .tau. is half the interecho time, .gamma. is the gyromagnetic ratio and T.sub.2B refers to the bulk relaxation. It is known in the art that for gas, which is a non-wetting phase, T.sub.1 =T.sub.1B .apprxeq.T.sub.2B. Therefore, given that the product D.sub.0 T.sub.1 of a gas after substitution in the expression above is an order of magnitude larger than oil and two orders of magnitude larger than brine, it can be seen that the already large DT.sub.1 contrast of gas can be enhanced even further by increasing the interecho time 2.tau. in order to allow the separation of two fluids that overlap in T.sub.1. The SSM is based on the above concept and is illustrated in FIGS. 2A-B.
Specifically, FIG. 2A shows synthetic T.sub.2 decay curves in a gas bearing zone. The solid curve is for the short interecho time (.apprxeq.0.6 msec) and the dashed curve corresponds to a longer interecho time of about 2.4 msec. FIG. 2B illustrates the T.sub.2 spectra obtained from the inversion of the synthetic echo trains in FIG. 2A. The solid spectrum corresponds to the shorter interecho time, while the dashed spectrum line corresponds to the longer interecho time. In FIG. 2B the solid spectrum line corresponds to both brine and gas. The signal from gas is shifted out of the detectability range, so that the single spectrum peak is due to brine.
While the DSM and the SSM methods discussed in the Akkurt et al. paper and briefly summarized above provide a possible working approach to detection of gas using solely NMR data, the methods also have serious disadvantages which diminish their utility in practical applications. Specifically, due to the fact that two separate logging passes are required, the Akkurt methods show relatively poor depth matching properties on repeat runs. Furthermore, subtraction of signals from different logging passes is done in the T.sub.2 spectrum domain which may result in losing valuable information in the transformation process, especially when the received signals have low signal-to-noise ratios (SNRs). In fact, for a typical logging pass, low hydrocarbon index (HI) of the gases in the formation, and relatively long T.sub.1 times generally lead to low SNR of the received signals. After transformation into the T.sub.2 spectrum domain even more information can be lost, thus reducing the accuracy of the desired parameter estimates. Finally, the Akkurt et al. paper does not indicate ways of solving additional problems such as accounting for low gas saturation in the sensitive volume, the presence of gases other than methane, and the temperature dependency of the filed gradient.
In summary, while some techniques have been developed in the prior art to extract information about the structure and the fluid composition of a geologic formation, so far no consistent NMR well logging method has been proposed to accurately and efficiently interpret these measurement parameters by accounting for the different effects of individual fluids. This lack may lead to inaccurate or misleading log data interpretation which in turn can cause costly errors in the oil exploration practice. Therefore, there is a need for a NMR system and method for providing consistent and accurate evaluation of geologic formations using a combination of substantially simultaneous log measurements to take into account the effects of different fluids.